1. Field of Disclosure
Embodiments disclosed herein generally relate to methods and apparatus to support and/or move tubular members. More specifically, embodiments disclosed herein relate to apparatus that are used to dispose one or more tubular members into subterranean wellbores, such as within the oil and gas industry.
2. Background Art
In oilfield exploration and production operations, various oilfield tubular members are used to perform various tasks, including, but not limited to, drilling and casing drilled wellbores. For example, an assembly of threaded pipes, known in the industry as a drill string, may be used to rotate a drill bit at a distal end thereof to create the wellbore. Furthermore, after a wellbore has been created, a casing string may be disposed downhole into the wellbore and cemented in place to stabilize, reinforce, and/or (among other functions) isolate portions of the wellbore.
As such, strings of drill pipe and casing may be connected together, such as end-to-end by threaded connections, in which a male “pin” threaded member of a first tubular member is configured to threadably connect to a corresponding female “box” threaded member of a second tubular member. Alternatively, a tubular string may be made-up of a series of male-male ended casing joints coupled together by female-female couplers. The process by which the threaded connections are screwed together is called “making-up” a threaded connection, and the process by which the connections are disassembled is referred to as “breaking-out” the threaded connection. As would be understood by one having ordinary skill, individual pieces (or “joints”) of oilfield tubular members may come in a variety of weights, diameters, configurations, and lengths.
Referring to FIG. 1, a schematic view of a drilling rig 101 used to run a drill string 115 of one or more tubular members 111 (e.g., casing, drill pipe, etc.) downhole into a wellbore is shown. As shown, drilling rig 101 includes a frame structure known as a “derrick” 102, from which a traveling block 103, a first gripping apparatus 105 (e.g., a casing running tool or conventional string elevator), a top drive assembly 145, and a second gripping apparatus 107 (e.g., slip assembly or spider) may be used to manipulate (e.g., raise, lower, rotate, hold, etc.) a tubular member 111. Traveling block 103 may be suspended from or near the top of derrick 102, in which traveling block 103 may move up-and-down (i.e., vertically as depicted) to raise and/or lower tubular member 111. Traveling block 103 may be a simple “pulley-style” block and may have a hook 104 from which objects below (e.g., first gripping apparatus 105 and/or top drive assembly 145) may be suspended.
Additionally, first gripping apparatus 105 may be coupled below traveling block 103 (and a top drive assembly 145 if present) to selectively grab or release a tubular member 111 to be raised and/or lowered within and from derrick 102. Further, top drive assembly 145 may include one or more guiding rails and/or a track 108 disposed adjacent to top drive assembly 145. Guiding rails or track 108 may be used by top drive assembly 145 to support and guide top drive assembly 145 as top drive assembly 145 is raised and/or lowered within derrick 102.
A typical top drive assembly may include pipe handling equipment used to make-up and break-out connections of drill string when sections are to be added or removed from the string. Further, a top drive assembly may include a torque wrench that may be connected permanently to a source of hydraulic or other power that may be operated, such as remotely. As such, a top drive assembly may be used to make-up and break-out pipe connections as well as to provide the power necessary to drill the well. An example of a top drive assembly is disclosed within U.S. Pat. No. 4,449,596, filed on Aug. 3, 1982, and entitled “Drilling of Wells with Top Drive Unit,” which is incorporated herein by reference in its entirety.
Such pipe handling equipment that may be attached to top drive assembly 145 (e.g., the rotatable quill thereof) may be first gripping apparatus 105. Typically, first gripping apparatus 105 may include movable gripping members (i.e., slips) attached thereto and movable between various open and closed positions. In a closed position, first gripping apparatus 105 may support tubular member 111 so that tubular member 111 may be raised and/or lowered, and rotated if so equipped with a tubular running tool connected to a quill of top drive assembly 145. In an open position, first gripping apparatus 105 may release tubular member 111 and move away therefrom to allow tubular member 111 to be engaged with or removed from first gripping apparatus 105. For example, first gripping apparatus 105 may release (inner and/or outer surface of) tubular member 111 after tubular member 111 is threadably connected to drill string 115 supported by drilling rig 101.
Referring now to FIG. 2A, a perspective view of a gripping tool 205 disposed within a drilling rig 201 is shown. Drilling rig 201 includes a top drive assembly 245 suspended by a traveling block 203 and a hook 204, in which top drive assembly 245 is disposed along guiding rails 208. A gripping tool 205 may be suspended from top drive assembly 245, in which gripping tool 205 may be engaged with a tubular member 211 (e.g. casing) such as with at least one gripping member 249 may be disposed within the tubular member that may be used to grip an internal surface of tubular member 211. As such, FIG. 2A shows the gripping tool 205 as an internal gripping tool that grips an internal surface of tubular members. Further, the gripping tool 205 may have a seal member 206 attached thereto, such as a packer cup (as shown), in which the seal member 206 may removably attach to the gripping tool 205. As such, the seal member 206 may be able to threadably connect to the gripping tool 205, in which the seal member 206 may be able to sealingly engage with an inner surface of the tubular member 211.
An alternative embodiment for a gripping tool may be an external gripping tool, such as with an external gripping tool 305 shown in FIGS. 3A and 3B. As such, gripping tool 305 may allow gripping members 349 of gripping tool 305 to grip an external surface of tubular member 311. An example of an external gripping tool is disclosed within U.S. patent application Ser. No. 12/604,327, filed on Oct. 22, 2009, and entitled “External Grip Tubular Running Tool,” which is incorporated herein by reference in its entirety. As such, torque from top drive assembly 345 may be transferred further from gripping tool 305 to tubular member 311 and may be used to run tubular member 311 into a wellbore 350. Further, the gripping tool 305 may have a seal member 306 attached thereto, such as a packer cup, in which the seal member 306 may be able to sealingly engage with an inner surface of the tubular member 311.
Additionally, in FIGS. 2A and 2B, top drive assembly 245 may be raised and lowered along guide rails 208 by traveling block 203. This allows the weight disposed on tubular member 211 to be manipulated, e.g., to adjust for different drilling conditions downhole. For example, if running tubular member 211 in wellbore 250 becomes difficult and additional weight on tubular member 211 is needed to proceed with advancement of tubular member 211 downhole, top drive assembly 245 may be lowered by traveling block 203 along guide rails 208 to provide additional downward force to help further guide tubular member 211 into wellbore 250. Conversely, traveling block 203 may be used to raise top drive assembly 245 along guide rails 208 so as to reduce the weight on tubular member 211.
The process of drilling subterranean wells typically includes drilling a hole in the earth down to a reservoir or formation in which a substance is intended to be removed from or injected. Typically, when drilling a wellbore, the wellbore may be drilled in multiple sections, rather than a single section. After each section of the well is drilled, a casing string (e.g., a string of tubular members) may be landed within the drilled wellbore. Casing is usually assembled from multiple tubular members connected together and placed in the wellbore to form a conduit extending from the subterranean reservoir to the surface. Casing may prevent the wellbore from collapsing and may also provide a barrier to the flow of fluids between the formations that the wellbore penetrates. A string of casing is typically cemented in place once the string is run into the wellbore. The string of casing may have more than one section having a different diameter from other adjacent sections of casing.
Further, with reference to FIGS. 2A and 2B, gripping tool 205 (e.g., casing running tool) may be operatively connected to a top drive assembly 245 and may incorporate a method of picking up single joints of casing and stabbing them into the string. Prior to casing operations, gripping tool 205 may be operatively connected below top drive assembly 245 and may incorporate a set of slips 207 to grip the casing. These slips 207 may support the entire casing string and may transmit the torque required to make-up and rotate the casing connections. An elevator (not shown), e.g., a single joint elevator, supported by gripping tool 205 or otherwise disposed on the rig, may be used to lift the joints of casing to the well center so that each joint may be stabbed into the previous joint. Top drive mounted gripping tool 205 may be lowered into well 250 until gripping tool 205 may engage the new joint being added. The gripping members 249 of gripping tool 205 are set on the joint of casing and the top drive assembly may now be energized, applying the required torque through gripping tool 205 to casing connection 211. Further, gripping tool 205 may include a circulating tool (not shown) so that, at any point in the casing running process, the tool may seal to casing to supply fluid to the casing, e.g., allowing fluid circulation to the bore of the casing run into the wellbore.
As such, after drilling of each section of the wellbore is complete, a drill string, such as drill string 215 shown in FIG. 2B, may be removed from wellbore 250 periodically such that casing may be placed therein. This process commonly involves removing drill string 215 from wellbore 250 (e.g., tripping out of the hole), as shown in FIG. 2B, and using top drive supported gripping tool 205 (e.g., casing running tool) to run casing 211 down hole, as shown in FIG. 2A. Casing is commonly run into the bore one joint or stand at a time, in which each next joint may be picked up and connected to the top most joint of the casing string extending from the wellbore 250. Once the joint (or stand) of casing has been connected to the casing string, gripping tool 205 may be moved into engagement with the added joint and used to secure the casing string. The casing string may be lifted by the first gripping apparatus (e.g., shown as an internal gripping casing running tool), thus allowing a second gripping apparatus 207 (e.g., the spider) to release the casing string. Once second gripping apparatus 207 has released the casing string, the casing string may be lowered into wellbore 250, e.g., via the first gripping apparatus.
Once the desired length of casing string is made-up, the casing string may then be run downhole to a desired location. For example, in an offshore environment, the casing string may be run to a downhole hanger disposed adjacent to the seafloor using a landing string. Once the casing string is positioned into the desired location (e.g., hung from the downhole hanger), the landing string may be unlatched from the casing string disposed downhole, and the landing string may be removed (e.g., tripped out) from the borehole.
In such applications, the first gripping apparatus for a casing string, e.g., top drive connected casing running tool 205, may not be desirable to connect directly to or capable of engaging (e.g., gripping) to the landing string. Rather, as the casing running tool 205 is used to run casing 211 downhole, a landing string, which may have a smaller diameter than the casing, may not successfully connect to or engage with the casing running tool. In some embodiments, the second gripping apparatus (e.g., spider) at the floor of the rig may be capable of engaging (e.g., gripping and supporting) the casing string and/or the landing string. For example, when switching from running the casing string to running a landing string, first gripping apparatus, e.g., top drive connected casing running tool 205 drive mounted, used to run the casing string down hole may be disconnected from the drilling rig (e.g., the traveling block 203 and/or quill of the top drive), as shown in FIG. 2B, and the landing string may be engaged (e.g., supported) by the drilling rig by a landing string (e.g., drill string) elevator or by the rotatable quill of the top drive assembly 245. However, the time to rig up and down (i.e., mounting and dismounting) the first gripping apparatus (e.g., casing running tool) may be significant, particularly in light of the costs of drilling operations offshore. For example, when switching between running a casing string and running a landing string, one may have significant time savings by avoiding rigging up and/or down the first gripping apparatus (e.g., casing running tool or string elevator).
The time used during the mounting/dismounting of the gripping tool may slow production, and therefore may increase drilling costs. Further, this may cause casing to remain static in an open hole for extended periods of time and the circulation of fluids may also be stopped. This may cause down time which may be problematic when the fluid may need to be circulated in order to maintain the pressure of the well which may further extend production time and costs. Accordingly, there exists a need to utilize the tool used to run casing into a wellbore to accommodate for also running a landing string.